Gas separation is useful in many industries and can typically be accomplished by flowing a mixture of gases over an adsorbent material that preferentially adsorbs one or more gas components while not adsorbing one or more other gas components. The non-adsorbed components are recovered as a separate product.
One particular type of gas separation technology is swing adsorption, such as temperature swing adsorption (TSA), pressure swing adsorption (PSA), partial pressure swing adsorption (PPSA), rapid cycle temperature swing adsorption (RCTSA), rapid cycle pressure swing adsorption (RCPSA), rapid cycle partial pressure swing adsorption (RCPPSA), and not limited to but also combinations of the fore mentioned processes, such as pressure and temperature swing adsorption. As an example, PSA processes rely on the phenomenon of gases being more readily adsorbed within the pore structure or free volume of an adsorbent material when the gas is under pressure. That is, the higher the gas pressure, the greater the amount of readily-adsorbed gas adsorbed. When the pressure is reduced, the adsorbed component is released, or desorbed from the adsorbent material.
The swing adsorption processes (e.g., PSA and/or TSA) may be used to separate gases of a gas mixture because different gases tend to fill the micropore of the adsorbent material to different extents. For example, if a gas mixture, such as natural gas, is passed under pressure through a vessel containing an adsorbent material that is more selective towards carbon dioxide than it is for methane, at least a portion of the carbon dioxide is selectively adsorbed by the adsorbent material, and the gas exiting the vessel is enriched in methane. When the adsorbent material reaches the end of its capacity to adsorb carbon dioxide, it is regenerated by reducing the pressure, thereby releasing the adsorbed carbon dioxide. Then, the adsorbent material is typically purged and repressurized prior to starting another adsorption cycle.
The swing adsorption processes typically involve adsorbent bed units, which include adsorbent beds disposed within a housing and configured to maintain fluids at various pressures for different steps in a cycle within the unit. These adsorbent bed units utilize different packing material in the bed structures. For example, the adsorbent bed units utilize checker brick, pebble beds or other available packing. As an enhancement, some adsorbent bed units may utilize engineered packing within the bed structure. The engineered packing may include a material provided in a specific configuration, such as a honeycomb, ceramic forms or the like.
Further, various adsorbent bed units may be coupled together with conduits and valves to manage the flow of fluids through the cycle. Orchestrating these adsorbent bed units involves coordinating the steps in the cycle for each of the adsorbent bed units with other adsorbent bed units in the system. A complete cycle can vary from seconds to minutes as it transfers a plurality of gaseous streams through one or more of the adsorbent bed units.
Conventional processes are used to treat hydrocarbon containing streams containing CO2 to prepare the stream for LNG specifications. For example, a typical LNG specification requires the CO2 content to be less than 50 parts per million molar (ppm). Such stringent specifications are not applied on natural gas streams in typical pipeline networks. For example, the CO2 content for pipeline gas in a pipeline stream can be as high as 2% by volume. As such, for LNG facilities that use the pipeline gas as the raw feed, additional treatment steps may be necessary. For gas containing less than a few hundred ppm of CO2, a conventional pressure or temperature swing adsorption process may be used. However, as the CO2 content in the gas stream increases, this process becomes economically unviable. For gas containing higher amounts of CO2, an amine-solvent based separation system is commonly used. Such amine-solvent based separation systems have large foot print and weight, and involve large capital investments. Additionally, these systems involve the use of solvents, which have to be replenished as part of the process. Furthermore, the process requires a large molecular sieve unit to dehydrate the gas downstream of the amine separation system, as the gas is at water saturation conditions.
Unfortunately, conventional processes for processing LNG streams have certain limitations. With LNG operations, the size and weight of the conventional system may be problematic, which is further compounded for floating facilities. The excessive weight and footprint for conventional systems add to the complexity of the floating facility and increase the size of the facilities. Also, the additional size and complexity increase the capital investment costs along with the operating costs for the floating facilities. Further, as conventional processes use of solvents or other such materials that require frequent replenishment, the operating costs and complexity are increased. This aspect is further compounded if the floating facilities is remotely located and is difficult to access and resupply.
Accordingly, there remains a need in the industry for apparatus, methods, and systems that provided enhancements to the processing of feed streams into a LNG system. Further, a need exists for a reduction in cost, size, and weight of facilities for treatment of pipeline quality streams prior to liquefaction, which may be provided to a LNG system that has to comply with LNG specifications.